Determination of thermal properties of a formation

ABSTRACT

The present invention relates to methods and apparatus for making in situ thermal property determinations utilizing a heat source employed in wellbore stabilization procedures, well drilling, or well perforating, for example. In particular, using a heat source, such as a laser driller, to enable formation temperature measurements. Based on these measurements, thermal properties of the formation may be inferred.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

1. Field of the Invention

The present invention relates to the evaluation of downhole formationsfrom the in situ determination of thermal properties. More particularly,the present invention relates to the in situ determination of thermalproperties, such as specific heat, thermal conductivity, and thermaldiffusivity from wellbore temperature measurements. Still moreparticularly, the present invention relates to the in situ determinationof thermal properties performed while utilizing a heat source employedin wellbore stabilization, drilling, or perforating.

2. Description of the Related Art

Modern petroleum drilling and production operations demand a greatquantity of information relating to parameters and conditions downhole.Such information typically includes the characteristics of the earthformations traversed by the wellbore, and the location of subsurfacereservoirs of oil and gas. Samples of the formation and reservoir may beretrieved to the surface for laboratory analysis. However, to enhancedrilling and production operations, it is much more valuable to providereal-time access to the data regarding downhole conditions. Thus, it hasbecome commonplace to make in situ measurements of many formationproperties via wellbore logging tools, such as logging-while-drilling(LWD) and wireline tools, that may be operated by electromagnetic,acoustic, nuclear or electromechanical means, for example. These loggingtools enable in situ determinations of such properties as the porosity,permeability, and lithology of the rock formations; reservoir pressureand temperature in the zones of interest; identification of the fluidspresent; and many other parameters.

It has been suggested that thermal properties of the formation, such asthermal diffusivity, thermal conductivity, and specific heat (orspecific heat capacity), are valuable for determining rock and fluidproperties. Thermal diffusivity enables a determination of rockcharacteristics, such as whether the formation comprises sand,limestone, shale, or granite, for example. Specific heat enables adetermination of fluid properties, such as whether the formation issaturated with hydrocarbons or water. In particular, the specific heatof water is approximately twice the specific heat of a hydrocarbon,regardless of whether the hydrocarbon is a liquid or gas. Thermalconductivity enables further differentiation between liquid and gashydrocarbon-saturated formations. In particular, the thermalconductivity of a water-saturated formation is approximately twice thethermal conductivity of an oil-saturated formation, and the thermalconductivity of an oil-saturated formation is approximately twice thethermal conductivity of a gas-saturated formation.

Thermal conductivity (K), the physical property of a material thatdetermines how easily heat can pass through it, is defined by equation(1), which relates several thermal properties as follows:K≡ρ·C·κ  (1)where ρ is the material density, C is the specific heat capacity, and Kis the thermal diffusivity. Specific heat capacity (C) is defined as thequantity of heat required to raise the temperature of one unit of massof material by one temperature degree. Thus, the units of specific heatcapacity (C) may be calorie/gram° C., for example. Thermal diffusivity(κ) is defined as the rate at which heat is conducted during unsteadystate heat transfer.

To make thermal property determinations, the most common method is totake a sample of the formation downhole, retrieve it to the surface, andthen evaluate the sample in a laboratory. The laboratory method does notenable real-time data acquisition, and can only be accurate with respectto the particular sample acquired. Since formation properties typicallychange with depth, it is likely that the laboratory analysis will notprovide complete data for all zones of the formation. Other methodsinclude inferring thermal properties from ambient borehole temperaturesmeasured by conventional wellbore logging tools. This method has somelimitations, including the inability to make accurate measurementsthrough casing to determine formation properties behind the casing andthe cement that surrounds it.

Yet another known method for determining thermal properties is toprovide downhole a constant output heat source and to measure thetemperature relaxation over time, which enables accurate measurements inboth cased and uncased boreholes. U.S. Pat. No. 3,807,227 ('227 patent)and U.S. Pat. No. 3,892,128 ('128 patent) to Smith, Jr. disclose suchthermal well logging methods for determining specific heat and thermalconductivity, respectively. A single heat source and preferably threespacially separated thermal detectors are disposed on a well loggingtool that is moved vertically through a borehole while the thermalresponses are recorded. In particular, one thermal detector measuresambient temperature of the borehole at a particular depth before theheat source passes that depth. The other two thermal detectors measurethe temperature of the borehole at the same depth following the heatsource, each at a different time. In one embodiment, the heat source isdisclosed to be a heat drilling tip that melts the earth formations toproduce a borehole. Examples of modern heat drilling tips are disclosedin U.S. Pat. No. 5,735,355 to Bussod et al. comprising a rock meltingtool with an annealing afterbody that cools the molten rock, and U.S.Pat. No. 5,771,884 to Potter et al comprising a spallation head withrotating, circumferentially spaced jets that dispense flame jets, veryhot water, and/or air to spall the formation rock, or fuse the formationrock if spallation is not feasible.

The '227 patent discloses that in a borehole environment, the change intemperature (ΔT) is related to the radiated energy (Q) from the heatsource, the mass of the heated earth formation (M) and its compositespecific heat (C) as given by the relationship of equation (2):Q=C×M×ΔT  (2)

Similarly, the '128 patent discloses that thermal conductivity (K) isproportional to the time rate of heat transfer in the formation. The onedimensional relationship governing the energy transfer (ΔQ) during ashort period of time (Δt) in a formation having a temperaturedifferential (ΔT) over a length (ΔX) is given by Equation (3):

$\begin{matrix}{\frac{\Delta\; Q}{\Delta\; t} = {K \times \alpha \times \frac{\Delta\; T}{\Delta\; X}}} & (3)\end{matrix}$where α is a constant dependent on the geometry of the borehole, theformation, and the well logging tool; and K is thermal conductivity.Thus, according to the '227 patent and the '128 patent, the specificheat (C) and the thermal conductivity (K) of the formation can beinferred using equation (2) and equation (3), respectively, based ontemperature measurements. Using these inferred values, qualitativeevaluations of likely locations of water and hydrocarbon deposits can bemade.

U.S. Pat. No. 3,864,969 ('969 patent) to Smith, Jr. discloses twomethods for determining thermal conductivity (K) of the formation byheating one spot within the formation. In the first method, theformation is heated for a predetermined length of time to elevate thetemperature. Then the heat source is removed and the rate of temperaturedecay is measured over time until the formation returns to ambienttemperature. In the second method, the formation is heated by a constantoutput heat source and the formation's rate of temperature increase ismeasured to derive an indication of thermal conductivity (K).

Similarly, U.S. Pat. No. 4,343,181 (the '181 patent) to Poppendiekdiscloses a method for in situ determinations of the thermalconductivity and thermal capacity per unit volume of the earth. The '181patent teaches a probe containing a heater and two temperature sensorsspacially displaced from one another. The probe is positioned in theborehole at the level of interest and maintained at that position for aperiod sufficient for the probe to be in thermal equilibrium with itssurroundings. The probe is displaced from the borehole wall by a thinfluid annulus, and it is not in contact with the borehole wall. Thethermal gradient between the two temperature sensors is recorded withoutheat being applied. Then, the heater is turned on to apply heat at aconstant rate, and the thermal gradient between the temperature sensorsis recorded. The thermal conductivity and thermal capacity per unitvolume of the surrounding earth is determined by relating the actualtemperature curve to a calculated theoretical curve by best-fitmathematical methods. At short times, the thermal capacity is said todominate the temperature response curve, and at long times, the thermalconductivity is said to dominate.

Each of these prior in situ methods proposes utilizing a downhole heatsource that is provided for the sole purpose of taking thermalmeasurements. Although this approach is technically sufficient, andvaluable formation characteristics can be determined using thismethodology, this approach has largely been ignored in practice. Onepossible explanation is that operators are not willing to incuradditional capital and operating costs for a heat source that isprovided solely for thermal property measurements. Thus, most commercialdownhole systems do not include heat sources that enable in situmeasurements of thermal properties. Accordingly, at the present time,thermal property measurements are almost exclusively restricted toanalysis of samples in laboratories.

Further, although the '128 patent and the '227 patent mention theconcept of a heat drilling tip that may also be used as a heat sourcefor enabling in situ determinations of thermal properties, such heatdrilling tips have proven to be too slow for commercial success. Inparticular, the heat drilling tip is designed to spall or actually meltthe rock of the formation as the method of forming a borehole. However,because rock is very slow to spall or melt utilizing such techniques,the heat drilling tip progresses at only 3–6 feet per hour. Therefore,the heat tip has not achieved commercial recognition or success as aviable drilling alternative.

The present invention overcomes the deficiencies of the prior art byproviding a convenient in situ method of measuring formation thermalproperties, such as specific heat, thermal conductivity, and thermaldiffusivity. The method is suitable at multiple depths using acommercially viable heat source provided downhole for wellborestabilization, well drilling or well perforating.

SUMMARY

The preferred embodiments of the present invention feature apparatus andmethods for making in situ thermal property determinations utilizing adownhole heat source that may also be employed for wellborestabilization, well drilling, or well perforating. Temperaturemeasurements are downhole, and thermal properties of the formation maybe inferred from these measurements using conventional formulas.

Thus, the preferred embodiments of the present invention comprise acombination of features and advantages that overcome various problems ofprior methods and apparatus. The various characteristics describedabove, as well as other features, will be readily apparent to thoseskilled in the art upon reading the following detailed description ofthe embodiments of the invention, and by referring to the accompanyingdrawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the embodiments of the presentinvention, reference will now made to the accompanying drawings, inwhich like elements have been given like numerals, wherein:

FIG. 1 is a schematic of an exemplary conventional drilling system;

FIG. 2 is a schematic of an exemplary wellbore stabilization operation;

FIG. 2A is a cross-sectional end view of an exemplary multi-bore coiledtubing;

FIG. 3 is a schematic of another exemplary wellbore stabilizationoperation;

FIG. 4 is a schematic of a chemical oxygen-iodine laser (COIL);

FIG. 5 is a schematic of an exemplary laser drilling system; and

FIG. 6 is a schematic of an exemplary laser perforating system.

DETAILED DESCRIPTION

Laser technology has flourished in recent years, largely through theexpansion of atomic physics, the invention of fiber optics, and advancesin military defense capabilities. Through these efforts, tremendousadvances have occurred, for example, in laser power generation,efficiency and transmission capabilities. Improvements in lasers andother thermal technologies have made it possible to perform wellboreoperations, such as wellbore stabilization, drilling, and perforating,utilizing new techniques. Because thermal technologies offer significantadvantages over conventional methods, they are gaining rapid acceptancein the petroleum industry.

Lasers and other thermal technologies provide a heat source downhole toperform a primary function, such as wellbore stabilization, drilling, orperforating through casing. The heat source may also be utilized for thesecondary but important purpose of determining thermal properties of theformation. Accordingly, measurements can be made of the temperatureresponse of a borehole after it is heated by a heat source. Thetemperature measurements are then utilized to infer thermal properties,such as thermal conductivity, thermal diffusivity, and specific heat,according to conventional calculations.

Some of the perceived advantages of using lasers or other thermaltechnologies stem from problems encountered with conventional drillingmethods. Thus, referring initially to FIG. 1, there is depicted aconventional rotary drilling operation, which comprises mainly threesteps: drilling, casing, and completion. To drill a well in theconventional manner, a drilling rig 100 on the earth's surface 10conveys a drillstring 110 and a drilling assembly 120 with a drill bit125 on its lower end into a wellbore 130, forming an annular flow area135 between the drillstring 110 and the wellbore 130. The drillstring110 is rotated from the surface 10 by the drilling rig 100 while a densefluid, known as “drilling fluid”, is drawn from a reservoir 140 by apump 150 on the surface 10. The pump 150 discharges the drilling fluidthrough pump discharge line 155 into the drillstring 110, downwardlyinto the drilling assembly 120 as depicted by the flow arrows to powerthe drill bit 125 and to remove the cuttings from the wellbore 130. Thedrilling fluid exits the drill bit 125 and returns to the surface 10through the wellbore annulus 135. After reaching the surface 10, thedrilling fluid is cleaned and returned to the reservoir 140 via the pumpreturn line 160. Thus, the drilling fluid, which contains suspendeddrill cuttings, flows continuously through the drillstring 110downwardly to the bottom of the wellbore 130 and upwardly through thewellbore annulus 135 back to the fluid reservoir 140 while removingcuttings (debris) from the wellbore 130. During drilling, the density ofthe drilling fluid, commonly referred to as the “mud weight”, isoptimized to counterbalance the earth's fluid pressure in the formation175, thereby preventing the uncontrolled flow of fluids from theformation 175 into the wellbore 130, or preventing the drilling fluidfrom fracturing and flowing into the formation 175. The earth's fluidpressure is caused by the presence of water, crude oil, and pressurizedgas such as CO₂, H₂S, and natural gas, within the formation 175.

In more detail, as the wellbore 130 is drilled, the mud weight may bevaried from one formation zone to another to counterbalance the pressureof the formation 175. For example, if the lower zone 179 of theformation 175 is overpressured, the mud weight must be increased whendrilling through zone 179 to balance the formation pressure. However, byusing a heavier mud weight in the wellbore 130, the upper zone 177 ofthe formation 175 could be fractured if that zone 177 is underpressured.In contrast, if the lower zone 179 is underpressured, the mud weightmust be decreased when drilling through zone 179 to balance theformation pressure. However, by using a lighter mud weight in thewellbore 130, a blow-out may occur in the upper zone 177 of theformation 175 if that zone 177 is overpressured. Therefore, beforedrilling into the lower zone 179 with a different mud weight, a steeltubular known as “casing”, such as casing 180, is installed to line thewellbore 130 in the upper zone 177, thereby isolating that section ofthe wellbore 130 from the surrounding formation 175. The casing 180 isthen cemented 185 against the formation 175 to protect fresh watersupplies and other nonhydrocarbon fluids from contamination, and toprovide zonal isolation between hydrocarbon and non-hydrocarbon bearingzones. Thus, the cement 185 provides a barrier to separate zone 177 fromzone 179 behind the casing 180. This procedure of casing installationand cementing is repeated for each section of the wellbore 130corresponding to each formation zone 177, 179 as the well is drilleddeeper. Each subsequent casing string, such as casing 190, is set bylowering the casing 190 through the previously set casing 180.Therefore, casing 190 will have a smaller diameter than the previouslyset casing 180. Thus, when drilling a well, multiple casing strings 180,190 are disposed along the wellbore 130 and cemented 185, 195 intoplace, thereby isolating each zone 177, 179 in the formation 175. If thezones 177, 179 are not isolated by casing 180, 190 and cement 185, 195,problems such as blowouts, lost circulation, and unwanted fracturing ofthe formation 175 could occur. The last section of the well to bedrilled is the production borehole 132, which is in contact with thefluid reservoir 170.

Once all the casings 180, 190, have been installed and cemented 185, 195into place, the drillstring 110 and drilling assembly 120 are removedand another assembly (not shown) is run into the wellbore 130 to makeperforations through the casings 180, 190 so that hydrocarbons will flowfrom the formation 175 into the wellbore 130. Perforations are madethrough the casings 180, 190 that line hydrocarbon-bearing zones 177,179 of the formation 175, and the cement 185, 195 prevents fluids, suchas water, for example, from non-hydrocarbon bearing zones from flowingbehind the casings 180, 190, and through the perforations. A productiontubular (not shown) is then inserted into the wellbore 130 to carry thehydrocarbons back to the surface. The process of perforating the casings180, 190 and inserting the production tubing is known as “completion”.

Some of the perceived advantages of using lasers or other thermaltechnologies stem from problems encountered with the above-describedconventional methods of well drilling and completion. For example, manydrilling problems occur before the casing 180, 190 is run and cemented185, 195 into place because the wellbore 130 is unsealed andunprotected. An unsealed wellbore 130 adjacent an overpressured zoneenables the influx of fluids from the formation 175, which can result inpressure “kicks.” Further, an unsealed wellbore 130 adjacent anunderpressured zone enables the loss of drilling fluids into thesurrounding formation 175, which may lead to lost circulation, formationdamage, differential pressure sticking, borehole swelling, boreholefracture, and even borehole collapse. Accordingly, there is a need for amethod to protect the wellbore 130, even temporarily, after a newsection has been drilled until a permanent casing 180, 190 can beinstalled and cemented 185, 195 into place. Further, because the casings180, 190 telescope down in size from the top of the wellbore 130 to thebottom of the wellbore 130, and the driller may not know in advance thenumber of pressure zones 177, 179 that will be encountered, it isdifficult to predict with certainty the number of casings 180, 190 thatwill be required and the size of the production borehole 132. In somecases, the production borehole 132 is so small that the hydrocarbonscannot be produced fast enough to make the well economically viable.Accordingly, there is a need for a method to protect and isolate thewellbore 130 without setting intermediate casing strings that reduce thediameter of the production borehole 132.

Referring now to FIG. 2, there is depicted a schematic of one exemplarywellbore stabilization operation that protects and isolates the wellbore130. FIG. 2 depicts a coiled tubing drilling system 300 having a powersupply 305, a surface processor 310, and a coiled tubing spool 315. Aninjector head unit 320 feeds and directs the coiled tubing 325, whichmay be either metal or composite coiled tubing, from the spool 315downwardly into the wellbore 130. The coiled tubing 325 supports awellbore stabilization and drilling assembly 200 within the wellbore 130that comprises a standard drill bit 125 driven by a drill motor 205, anextruder 225, a heat source 220, and preferably a plurality oftemperature sensing devices 230, 240, 250, each of which is capable ofmeasuring the temperature of the formation 175 in its vicinity. Areservoir 270 on the surface 10 connects to a pump 265 via an inletconduit 275, and the pump 265 connects to an exit conduit 255 thatextends downwardly through the bore 322 of the coiled tubing 325 to theextruder 225. A standard wireline 260, such as a 7-conductor wireline,extends downwardly through the bore 322 of the coiled tubing 325 toconduct power from the surface power supply 305 to the wellborestabilization and drilling assembly 200 for operating the heat source220. The wireline 260 further conducts signals from the temperaturesensing devices 230, 240, 250 to the signal processing unit 310 on thesurface. It will be appreciated by those skilled in the art that thewellbore stabilization and drilling assembly 200 also containsappropriate power supply circuitry and data transmission circuitry (notshown) for operating the heat source 220 and temperature sensing devices230, 240, 250, and for transmitting measurements made thereby to thesurface for further processing.

In operation, drilling fluid is pumped through the bore 322 of thecoiled tubing 325 to power the drill motor 205, which in turn powers thedrill bit 125. Simultaneously, the extruder 225 and the heat source 220enable placement of a temporary liner 280 to line the wellbore 130 insections where casings have not yet been installed, such as along thelower borehole section 134 of FIG. 2. In particular, pump 265 pumps afusible liner material 210, such as polyethylene or polypropylene, forexample, from the reservoir 270 through the exit conduit 255 anddownwardly to the extruder 225, which extrudes the liner material 210onto the wall 136 of the lower borehole section 134. The fusible linermaterial 210 may be provided in the form of liquid or small solidpellets, for example, or any other suitable form. As the wellborestabilization and drilling assembly 200 reaches the lower boreholesection 134, preferably the ambient temperature of the formation 175 ismeasured by sensor 230 at a predetermined depth D. Then, after thefusible liner material 210 is extruded onto the wall 136 of the lowerborehole section 134, the heat source 220 is activated to heat thefusible liner material 210, thereby melting it. As the wellborestabilization and drilling assembly 200 advances, the melted fusibleliner material 210 is forced into the porosity of the formation 175, andas the liner material 210 cools, it creates a temporary liner 280 alongthe lower borehole section 134 as depicted in FIG. 2. In anotherembodiment, instead of pumping the liner material 210 through a separateconduit 255 extending through the coiled tubing bore 322, the coiledtubing 325 could have more than one bore. For example, as depicted incross-section in FIG. 2A, the coiled tubing 325 could comprise twobores, such as a central fluid bore 321 and an outer annular bore 323.The drilling fluid could flow through the central bore 321 and the linermaterial 210 could flow through the annular bore 323, or vice versa.There are a variety of other possible configurations for pumping theliner material 210 to the extruder 225.

Thus, the heat source 220 melts the fusible liner material 210 toproduce the temporary liner 280, while simultaneously heating theformation 175 in the vicinity of the heat source 220. As heat is appliedto the formation 175, measurements of temperature changes in theformation 175 induced in the vicinity of the temperature sensing devices230, 240, 250 enables the determination of thermal properties of theformation 175, as in conventional methods. In particular, as thewellbore stabilization and drilling assembly 200 moves downwardly, thetemperature sensing devices 230, 240, 250, which are spaciallyseparated, each pass depth D in the formation 175 at different timessuch that temperature measurements can be made at the same depth D overtime to measure the time rate of decay of the temperature at depth D.Alternatively, once the formation 175 has been heated to form thetemporary liner 280, the wellbore stabilization assembly 200 may be heldstationary, thereby keeping sensors 230, 240, 250 stationary within thewellbore 130. Then a plurality of temperature measurements may be madeat the depths d1, d2, d3 of each sensor 230, 240, 250 respectively, overtime, to measure the time rate of decay of the temperature at each depthd1, d2, d3. The temperature differentials and other measurements arethen used to infer thermal properties according to conventionalcalculations.

Referring now to FIG. 3, there is depicted a schematic of anotherexemplary wellbore stabilization operation. FIG. 3 depicts a coiledtubing drilling system 300 having a power supply 305, a surfaceprocessor 310, and a coiled tubing spool 315. An injector head unit 320feeds and directs the coiled tubing 325, which is composite coiledtubing, from the spool 315 downwardly into the wellbore 130 to support awellbore stabilization and drilling assembly 330 on its lower end. Thepower supply 305 may be connected by electrical conduits 307, 309 toelectrical conduits in the wall of the composite coiled tubing 325.Alternatively, the power supply 305 may be connected to a wireline 260that extends through the bore 322 of the coiled tubing 325, as depictedin FIG. 2. Further, the surface processor 310 includes data transmissionconduits 312, 314 that may be connected to data transmission conduitsalso housed in the wall of the composite coiled tubing 325.Alternatively, the surface processor 310 may be connected to a wireline260 that extends through the bore 322 of the coiled tubing 325, asdepicted in FIG. 2.

The wellbore stabilization and drilling assembly 330 includes many ofthe same components as the wellbore stabilization and drilling assembly200 of FIG. 2. However, the assembly 330 of FIG. 3 includes a downholereservoir 340 rather than the surface reservoir 270, pump 265, andconduit 255 extending through the coiled tubing 325, as shown in FIG. 2.

In operation, drilling fluid is pumped through the bore 322 of thecoiled tubing 325 to power the drill motor 205, which in turn powers thedrill bit 125. Simultaneously, the extruder 225 and the heat source 220enable placement of a temporary liner 280 to line the wellbore 130 insections where casings have not already been installed, such as alongthe lower borehole section 134 of FIG. 3. To create the temporary liner280, the fusible liner material 210 is selectively dispensed, such asvia an actuatable valve 345, for example, from the downhole reservoir340 into the extruder 225, which extrudes the liner material 210 ontothe wall 136 of the lower borehole section 134. Then, after the fusibleliner material 210 is extruded, the heat source 220 melts the fusibleliner material 210. In an alternate embodiment, the downhole reservoir340 may be positioned above another type of heat source (not shown),such that the fusible liner material 210 may be selectively dispensedinto the heat source to be heated therewithin before being extruded.Thus, in the alternate embodiment, the extruder 225 extrudes meltedliner material 210 onto the lower borehole wall 136. Once the linermaterial 210 is extruded and melted, then as the wellbore stabilizationand drilling assembly 330 advances, it forces the melted fusible linermaterial 210 into the porosity of the wellbore 130 to create a temporaryliner 280.

Thus, the heat source 220 or the alternate heat source (not shown) meltsthe fusible lining material 210 to produce a temporary liner 280, whilesimultaneously heating the formation 175 in the vicinity of the heatsource 220. As heat is applied to the formation 175, measurements oftemperature changes of the formation 175 induced in the vicinity oftemperature sensing devices 230, 240, 250 enable the determination ofthermal properties of the formation 175, as in conventional methods. Inparticular, as the wellbore stabilization and drilling assembly 330moves downwardly, the temperature sensing devices 230, 240, 250, whichare spacially separated, will each pass depth D in the formation 175 atdifferent times such that temperature measurements can be made at thesame depth D to measure the time rate of decay of the temperature atdepth D. Alternatively, once the formation 175 to form the temporaryliner 280, the wellbore stabilization assembly 330 can be heldstationary, thereby keeping sensors 230, 240, 250 stationary within thewellbore 130. Then a plurality of temperature measurements may be madeat the depths d1, d2, d3 of each sensor 230, 240, 250 respectively, overtime, to measure the time rate of decay of the temperature at each depthd1, d2, d3. The temperature differentials and other measurements arethen used to infer thermal properties according to conventionalcalculations.

The heat source 220 in the assemblies 200, 330 of FIG. 2 and FIG. 3,respectively, may comprise any source of heat, such as for example, aheat tip that reaches sufficient temperatures to melt the fusible linermaterial 210. In another embodiment, the heat source 220 comprises alaser as will be described in more detail hereinafter. A laser can reachtemperatures capable of melting the formation 175 rock, and when themolten rock cools, a liner is formed such that no fusible liner material210 is required.

Beyond wellbore stabilization, lasers are now being utilized fordrilling. Unlike conventional drilling, in which the drilling rate isdetermined by the weight-on-bit (WOB), mud circulation (cuttingsremoval) rate, rotary speed, hydraulic horsepower, bit design andwellbore size, the rate of penetration achieved with a laser may onlydepend on wellbore size and delivered power. Moreover, no out-of-balanceor out-of-axis turning is expected to occur with a laser-drilledwellbore, and, because a laser head does not contact the rock, there isno need to stop drilling to replace a mechanical bit.

A laser is basically a device that converts energy of some form(electrical, chemical, heat, etc.) into photons, which iselectromagnetic radiation. The photons created through stimulatedemission form a narrow beam of monochromatic coherent light energy thatwhen focused into an intense beam can be used to fragment, melt orvaporize rock, depending upon the power delivered, and the operatingparameters associated with pulsing the laser.

Referring now to FIG. 4, there is shown a schematic of one embodiment ofa laser that could be used for drilling a wellbore; namely a chemicaloxygen-iodine laser (COIL) 400. The overall COIL process is conceptuallysimple. Basic hydrogen peroxide (BHP) 410 when mixed with chlorine gas420 in a gas generator 430 produces oxygen in an excited state (calledthe oxygen singlet delta 440). The byproduct of this reaction is heat435 and brine 445, which is common in the oilfield. The oxygen singletdelta 440 is combined with molecular iodine 450 in a supersonic mixingnozzle 460, which causes both the dissociation of molecular iodine toatomic iodine and produces iodine in an excited state, creating thelaser gain region 465. In the laser gain region 465, laser cavitymirrors 470 stimulate excited iodine to form atomic iodine, releasingphotons, or “packets” of light energy that is the laser beam 475. Theexhaust gases are scrubbed in a scrubber 480 to remove any residualiodine and chlorine.

While a COIL has been described as one type of laser that could be usedfor purposes of laser drilling, a number of alternate laser systemscould also be used, including hydrogen fluoride (HF), deuterium fluoride(DF), carbon dioxide (CO₂), carbon monoxide (CO), free electron laser(FEL), neodymium:yttrium aluminum garnet (Nd:YAG), and krypton fluorideexcimer (KrF (excimer)) lasers, for example. Lasers can operate incontinuous-wave (CW), pulsed, and repetitively pulsed (RP) modes. Themain energetic parameter for a CW laser is the output power, for apulsed laser the output energy, and for a RP laser the average power andpulsed energy. Each of these lasers operates at a specific wavelengthrange, except for the FEL, which may be tuned to virtually anywavelength in continuous wave (CW) mode.

FIG. 5 schematically depicts one embodiment of a laser drilling system500 as it is drilling a wellbore 130 into a formation 175. The laserdrilling system 500 comprises a laser 510 on the surface, such as a FELor COIL, connected to one or more fiber optic elements 515 comprising abundle that extends downwardly through a coiled tubing drillstring 325and connects to a series of lenses 520, 525, 530 on the lower end of alaser drilling assembly 550. In an alternate embodiment, a smallerlaser, such as a diode laser (not shown), is small enough to fit withinthe wellbore 130, such as at the lower end of the laser drillingassembly 550, thereby eliminating the need for fiber optic elements 515.

In FIG. 5, the laser drilling assembly 550 is suspended within thewellbore 130 by a coiled tubing system 300 having a power supply 305, asurface processor 310, and a coiled tubing spool 315. An injector headunit 320 feeds and directs the coiled tubing 325, which may be eithermetal or composite coiled tubing, from the spool 315 downwardly into thewellbore 130 to support the laser drilling assembly 550. The powersupply 305 is shown connected to a wireline 260 that extends through thebore 322 of the coiled tubing 325 and conducts power from the powersupply 305 to the laser drilling assembly 550. Alternatively, the powersupply 305 may be connected to electrical conduits in the wall of thecoiled tubing 325. Further, the surface processor 310 connects to thewireline 260 to form a bi-directional telemetry system. In particular,the wireline 260 conducts data signals from several temperature sensors552, 554 and 556 disposed on the laser drilling assembly 550 to thesurface processor 310, and the surface processor 310 may also generatecommand signals that are conducted downhole via the wireline 260 to thelaser drilling assembly 550 to alter the laser drilling operations.Alternatively, instead of the wireline 260, the surface processor 310may be connected to data transmission conduits housed in the wall of thecoiled tubing 325 to form the bi-directional telemetry system.

In operation, the laser drilling system 500 transfers light energy fromthe laser 510 on the surface, down the one or more fiber optic elements515 to the series of lenses 520, 525, 530. The lenses 520, 525, 530direct a laser beam to cut the rock and extend the wellbore 130. As thelaser 510 transfers light energy downhole, heat is produced that willenable time rate of decay temperature measurements to be taken by thetemperature sensors 552, 554, 556. In particular, as the laser drillingassembly 550 moves downwardly to extend the wellbore 130, thetemperature sensors 552, 554, 556, which are spacially separated, willpass a depth D in the formation 175 at different times such thattemperature measurements can be made at the same depth D over time.Thus, a temperature differential can be determined from which thermalproperties can be inferred by conventional methods.

One of the primary benefits of making these real-time thermal propertydeterminations is to enhance laser drilling operations. Thermalproperties, such as thermal diffusivity, are especially valuable fordetermining properties of the formation rock. For example, the laser 510utilized for drilling will have different pulse rates and differentpreferred operating parameters, such as how long and how often to pulsethe laser, for example, depending upon the type of formation rock. Insome cases, the same amount of laser energy will melt one type of rockwhile it will vaporize another. Thus, real-time information aboutformation properties enables improvements to be made in the laserdrilling process. In particular, as drilling progresses, temperaturemeasurements are made via temperature sensors 552, 554, 556 disposed onthe drilling assembly 550. The wireline 260 conducts signals from thetemperature sensors 552, 554, and 556 to the surface processor 310 wherethe data is processed to determine thermal properties of the formation175. Then, various parameters of the laser 510, such as the pulse rate,for example, may be adjusted depending upon the characteristics of theformation 175.

FIG. 6 schematically depicts the laser 510, the one or more fiber opticelements 515, and the lenses 520, 525, 530 being utilized to perforatecasing 190 in the middle section 138 of the wellbore 130. In thisconfiguration, the laser 510 transfers light energy down the fiber opticelements 515 to the series of lenses 520, 525, 530. The lenses 520, 525,530 then direct a laser beam to perforate the casing 190, cement 195,and formation 175 to form a perforation 176.

In another embodiment, since light energy from a laser, such as laser510, can be conducted along a fiber optic element 515 for shortdistances, the lenses 520, 525, 530 can be eliminated. In thisembodiment, the laser 510 transfers light energy down the one or morefiber optic elements 515, and the ends of the fiber optic elements 515are positioned to direct a laser beam to perforate the casing 190,cement 195, and formation 175. It would also be possible to point theend of each one of the fiber optic elements 515 to various differentpositions along the length of the casing 190 to form multipleperforations 176 simultaneously. For example, assuming there are ten(10) fiber optic elements 515 bundled to a single laser source 510, theend of each one of the fiber optic elements 515 may be pointed to adifferent location along the casing 190. Then light energy from thelaser 510 may be conducted to the ends of the individual fiber opticelements 515 in sequence to create ten perforations 176. In particular,since each pulse of the laser 510 lasts only briefly when perforating soas to spall rather than melt the rock, the light energy can be conducted(pulsed) to each fiber element 515 in sequence at a rapid pace togenerate the ten perforations 176, with the sequence returning to thefirst perforation in time for the next pulse. This sequence would berepeated multiple times to create completed perforations along thecasing 190 length. The laser 510 could be located on the surface asshown in FIG. 6, or alternatively, the laser 510 could be disposedwithin the wellbore 130. It may also be possible to form and extend aperforation tunnel 177 using a fiber optic element 515 by projecting theelement 515 out into the perforation 176 and pulsing the laser 510 tocontinue spalling the rock and form a progressively longer perforationtunnel 177.

A properly pulsed laser 510 may create fewer but higher qualityperforations 176 as compared to conventional perforating methods. Inparticular, using a conventional perforator that dispenses shapecharges, a plurality of perforations can be created in a short period oftime. However, many of these perforations do not extend deep enough intothe formation, or they may be blocked with casing and rock debris thatis forced into the perforation and surrounding formation by the shapecharge, thereby reducing the effective produceability of the formation.Therefore, although a large number of perforations can be created usinga conventional perforator, few of the perforations will produce. Forexample, if 50 feet of casing length is perforated, approximately only 5feet of perforations may actually produce. In contrast, the perforations176 created with a laser 510 do not get blocked with debris and can beextended to form a tunnel 177 in the formation 175 as needed. In fact,as reported in “Temperature Induced by High Power Lasers: Effects onReservoir Rock Strength and Mechanical Properties”, SPE/ISRM 78154, dataindicates that in many cases the effective permeability of the rockaround the tunnel 177 is actually increased relative to that of thevirgin formation 175. Therefore, it is possible for a majority of thelaser-created perforations 176 to produce.

Once again, heat is generated in the formation 175 as a result of thelaser perforating operation performed by any of the above-describedmethods. Temperature probes can be installed in a perforation tunnel 177to measure the temperature relaxation at one or more positions withinthe perforation tunnel 177 over time. In one embodiment, the temperatureprobes comprise a fiber optic element 515, which, as known in the art,can make distributed measurements along the length of the fiber. Thefiber optic element 515 may be part of the bundle connected to the laser510, or it may be a separate fiber optic element connected to anotherlaser. Accordingly, since a fiber optic element 515 can be used to spallrock to form perforations 176 and tunnels 177, and can also be used totake distributed temperature measurements, the same laser 510 and fiberoptic elements 515 can be used for both purposes. In such a case, thelaser 510 would be operated in one mode to form the perforations 176 andtunnels 177 and in a different mode to make temperature measurements.

In more detail, to make distributed temperature measurements using afiber optic element 515, the laser 510 is operated to pulse light energydown the fiber optic element 515. Temperature measurements can be madeat each point along the length of the fiber 515. Most distributedtemperature sensing systems utilizing fiber optic elements 515 rely onOptical Time Domain Reflectometry (OTDR), which is known in the art, todetermine the spatial position of an individual measurement. OTDR is astandard method of determining losses along the length of an opticalfiber 515. The time it takes for the reflective light to return to thesource indicates the precise position along the fiber 515 where themeasurement is being taken. The characteristics of the reflective lightare analyzed using known techniques, such as Raman backscattering, todetermine the temperature at that precise position. Thus, for each pulseof the laser 510, the operator can obtain reflective light measurementsat different times corresponding to different positions along the fiberoptic element 515. The operator can then pulse the laser 510 again andrepeat the measurement sequence at each position along the fiber opticelement 515, and so on. This will provide a number of temperaturemeasurements at each position such that temperature differentials can bedetermined from which thermal properties can be inferred by conventionalmethods. Although the length of the fiber optic element 515 is locatedat approximately the same depth in the formation 175 when disposedwithin a perforation tunnel 177, distributed temperature measurementsalong the length of the fiber 515 are valuable for determining theproperties of the formation 175 with greater accuracy, and fordetermining the required depth of the perforation tunnels 177 to engageformation zones containing the most hydrocarbons.

One of the primary benefits of making real-time thermal propertydeterminations is to enhance laser perforating operations based upon thecharacteristics of the rock comprising the formation 175. For example,as previously described, temperature measurements may be made within aperforation tunnel 177 via a temperature probe (not shown) or a fiberoptic element 515, and the temperature signals may then be transmittedto the surface processor 310 to determine thermal properties of theformation 175. Then, various parameters of the laser 510, such as thepulse rate, intensity, and duration, can be adjusted based upon thereal-time determination of thermal properties of the formation 175,thereby improving the laser perforating operation.

Thus, the preferred embodiments of the present invention take advantageof the heat from a thermal drilling, wellbore stabilization, orperforating process to perform thermal measurements. The thermalmeasurements may be performed simultaneously or near simultaneously withthe drilling operations. The sensors thus provide in situ temperaturemeasurements that permit the computation of thermal properties of theformation as described in the earlier '128 patent, the '227 patent andthe '969 patent to Smith, Jr.

While preferred embodiments of the present invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit or teaching of this invention. Forexample, a fiber optic element and laser could be utilized to takedistributed temperature measurements along the wellbore during thermaldrilling or wellbore stabilization operations in addition toperforating. Thus, the embodiments described herein are exemplary onlyand are not limiting. Many variations and modifications of the methodsand apparatus are possible and are within the scope of the invention.Accordingly, the scope of protection is not limited to the embodimentsdescribed herein, but is only limited by the claims which follow, thescope of which shall include all equivalents of the subject matter ofthe claims.

1. A method for determining the thermal properties of a downholeformation, comprising: cutting and heating the formation with a laserbeam adjacent a selected depth level within a wellbore extending intothe formation; measuring a first temperature of the formation at theselected depth level at a first time after heating the formation;measuring a second temperature of the formation at the selected depthlevel at a second time after heating the formation; and combining thetemperature measurements to derive an indication of the thermalproperties of the formation according to known mathematicalrelationships.
 2. The method of claim 1 further comprising measuring theambient temperature of the formation at the selected depth level.
 3. Themethod of claim 1 wherein the laser beam is used for measuring thetemperatures.
 4. The method of claim 1 wherein cutting the formationcomprises transferring light energy from a laser to at least onecomponent that directs the laser beam toward the formation.
 5. Themethod of claim 4 wherein the at least one component is a series oflenses.
 6. The method of claim 5 wherein the light energy is transferredfrom the laser through at least one fiber optic element to the lenses.7. The method of claim 4 wherein the at least one component is oneormore fiber optic elements.
 8. The method of claim 4 wherein the laseris disposed within the wellbore.
 9. The method of claim 1 whereincutting the formation comprises extending the wellbore.
 10. The methodof claim 1 wherein cutting the formation comprises perforating through acasing lining the wellbore.
 11. The method of claim 10 furthercomprising forming a perforation tunnel in the formation.
 12. The methodof claim 11 wherein measuring the temperatures comprises inserting atemperature probe into the tunnel.
 13. The method of claim 12 whereinthe temperature probe comprises a fiber optic element.
 14. The method ofclaim 13 wherein measuring the temperatures comprises making distributedtemperature measurements along the fiber optic element.
 15. The methodof claim 11 further comprising extending the tunnel by transferringlight energy from a laser to a fiber optic element disposed within thetunnel.
 16. The method of claim 15 wherein measuring the first andsecond temperatures comprises making distributed temperaturemeasurements along the fiber optic element.
 17. The method of claim 1wherein measuring the temperatures comprises spacing at least twotemperature sensors axially with respect to the wellbore and moving eachof the temperature sensors to the selected depth level.
 18. The methodof claim 17 wherein the at least two temperature sensors comprise afiber optic element.
 19. The method of claim 1 wherein measuring thetemperatures comprises positioning a temperature sensor at the selecteddepth level and maintaining the sensor at the selected depth level whilemeasuring the first temperature and the second temperature.
 20. Themethod of claim 19 wherein the temperature sensor comprises a fiberoptic element.
 21. The method of claim 1 wherein the thermal propertiesof the formation comprise one or more of the following: thermalconductivity, thermal diffusivity and specific heat.
 22. The method ofclaim 1 further comprising altering the operation of the laser beambased on the thermal properties of the formation.